1. Field of the Invention
This invention relates to producing wells having an artificial lift system for removing liquid from an underground formation. In one of its aspects, the invention relates to improved methods of and systems for control of artificial lift systems utilizing pressure measurements and pressure manipulation to detect the liquid level in the well bore to thereby increase the efficiency, operational predictability and to automate the artificial lift systems. In another of its aspects, the invention relates to the monitoring of production gas from a gas producing well and detection of the liquid level in the well bore to thereby control the artificial lift system to maximize gas production from the well while simultaneously maximizing artificial lift system performance and efficiency.
2. Description of Related Art
Artificial lift systems are commonly used to extract fluids, such as oil, water and natural gas, from underground geological formations. Oftentimes, the formations are more than 1,000 feet below the surface of the earth. The internal pressure of the geological formation is often insufficient to naturally raise commercial quantities of the liquid or gas from the formation through a bore hole. When the formation has a sufficient internal pressure to naturally lift the liquid from the formation, the natural pressure is often inadequate to produce the desired flow rate. Therefore, it is desirable to artificially lift the liquid from the formation by means of an artificial lift system.
Typically, the formation can comprise several separate layers containing the liquid and gas or can comprise a single large reservoir. A bore hole is drilled into the earth and passes through the different layers of the formation until the deepest layer is reached. Due to economic considerations, many bore holes extend only to the deepest part of the productive formation. In certain applications it is desired to extend the bore hole beyond the bottom of the productive formation. The portion of the bore hole that extends beyond the bottom of the formation and into the substrata is known as a xe2x80x9crat hole.xe2x80x9d The location and depth of the bore hole is carefully controlled because of the great expense in drilling the bore hole.
After the bore hole is drilled, the bore hole is usually lined with a casing along its entire length to prevent collapse of the bore hole, to control reservoir pressure and to protect surface water from contamination. However, the bore hole is often only lined with the casing to the top of the gas and liquid containing formation, leaving the lower section of the bore hole uncased. The uncased section is referred to as an open hole. The casing is cemented in place and sealed at surface by a wellhead and can have one or more pipes, tubes or strings (metal rods) disposed therein and extending into the bore hole from the wellhead. One of the tubes is typically a production tube, which is used to carry liquid to the surface.
Currently, many different types of artificial lift systems are used to lift the liquid from the formation. The most common artificial lift systems are: progressive cavity pumps, beam pumps and subsurface gas lift (SSGL). A progressive cavity pump is relatively expensive, approximately $20,000 to install, but can deliver relatively large volumes of liquid and remove all the liquid from the formation. A progressive cavity pump can comprise an engine or electric motor driven hydraulic pump connected to a hydraulic motor mounted on the top of the wellhead and connected to a pump at the bottom of a production tube. The hydraulic motor turns a rod string that is connected to a pump rotor, which turns with respect to a pump stator. Alternately, some progressive cavity pumps are driven by an electric motor attached to the top of the well head. The pump rotor is helical in shape and forms a series of progressive cavities as it turns to lift or pump the liquid from the bottom of the well bore into the production tube and to the surface. Although the progressive cavity pump is satisfactory in raising liquid from the formation, the hydraulic pump system requires a containment building and liner in the event of an oil leak. The possibility of an oil leak in the progressive cavity pump system also raises environmental concerns because many of the bore holes are drilled in environmentally sensitive or wilderness areas. The progressive cavity pump also requires, in certain applications, at least 100 feet of a rat hole, which adds extra cost. Of the previously mentioned artificial lift systems, the progressive cavity pump has the highest maintenance costs and greatest amount of down time requiring rig service. This down time often results from a lack of good liquid level control which allows the well to be pumped off causing damage to the pump system. Also, a soft seal stuffing box which must be lubricated regularly is used to seal around the rotating rod string and acoustic annular liquid levels must be obtained at regular intervals to ensure that the liquid is adequately high above the pump so that it does not run dry and destroy itself.
A beam pump is also relatively expensive, approximately $18,000, to install but can also remove all the liquid from the formation. The beam pump comprises a pivotally mounted beam that is positioned over the wellhead and connected to a rod string extending into the production tube within the casing in the bore hole. The lower end of the rod string is connected to a pump disposed near the bottom of the well bore. The beam pump can be operated by a gas engine or an electric motor. The beam pump has several disadvantages. First, there are many environmental concerns. There may be leakage in the engine or gear box of the power source, requiring construction of a containment area. Further, if an electric motor is used in place of the gas engine, it is necessary to run a power line to the electric motor, which often destroys or degrades the surrounding environment. The beam pump, like the progressive cavity pump, has many moving components that require regular lubrication. The beam pump also uses a soft seal stuffing box to seal around the reciprocating rod string to contain liquids and gases produced up the production tube.
The SSGL is the least expensive artificial lift system to install, approximately $7,500. The SSGL uses pressurized gas carried by a separate tube, commonly referred to as a side string, from the surface to the lower end of the production tube to eject the liquid in the production tube to the surface upon injection of a blast of pressurized gas. The production tube usually has at its lower end a one-way valve called a xe2x80x9cstanding valvexe2x80x9d which permits liquid standing in the formation to enter the production tube and rise in the production tube to the level of liquid in the formation. Often the SSGL system will have a plunger disposed within the production tube, but a plunger is an optional device to provide mechanical advantage for the blast of injection gas.
The SSGL is the most environmentally friendly, maintenance free and energy efficient of the three commonly used artificial lift systems. Unlike the other artificial lift systems, the subsurface gas lift system requires no systematic lubrication of the gas regulator and the motor valve. The SSGL maintains greater integrity of the well head in controlling the possibility of liquid leaks because the well head components are hard piped with no friction oriented soft seal such as is found in the stuffing boxes of the progressive cavity and beam pumps. The SSGL is virtually silent during operation and has very little surface equipment compared to a beam pump or progressive cavity pump. Therefore, it has less audible and visual impact on the surrounding environment.
The greatest disadvantage of the SSGL is that it becomes less efficient and more difficult to control as more and more liquid is removed from the formation. The SSGL can only raise the column of liquid in the production tube. The column of liquid in the production tube is equal to the level of liquid in the annulus and therefore the level of liquid in the formation if the production tube and annulus are equalized into a common line at surface. As more and more liquid is removed from the formation, the level of liquid in the formation decreases. Therefore, as the level of liquid in the production tube decreases and a continuously smaller and smaller amount of liquid is raised for substantially the same amount of energy. As the liquid level in the subsurface gas lift system decreases or the influx of liquid to the well bore becomes erratic, there becomes a point where it is no longer operationally predictable, safe or productive to use the subsurface gas lift system. Oftentimes, the subsurface gas lift system is operated as a crippled and inefficient system without a plunger or replaced with a beam pump and its accompanying undesirable attributes. Optionally, a xe2x80x9crat holexe2x80x9d can be bored with the bore hole in a subsurface gas lift system so that most of the liquid can be raised from the formation by placing the gas injection point below the level of the formation and in the rat hole. However, many bore holes were drilled without a rat hole before artificial lift became a generally accepted method of production and the cost associated with boring a rat hole is such that most companies still prefer to drill little, if any, rat hole.
Another disadvantage that is common to all artificial lift systems is that as the liquid level decreases or the influx of liquid to the well bore becomes erratic, the systems become operationally more difficult to efficiently control without damaging themselves regardless of the depth of the rat hole. In the event of no liquid level, the progressive cavity pump will quickly torque up and destroy the down hole pump, twist off the rod string or destroy the stator assembly. The beam pump will begin to pound as gas is drawn into the pump, the end result of which will be a scored or damaged pump barrel and eventually a parted rod string. The SSGL may xe2x80x9cdry cycle,xe2x80x9d a condition where the plunger arrives at the surface and bottom of the well with no liquid cushion and, therefore, possibly at a damaging velocity. As the level of liquid decreases in an SSGL system, there is an increased need to use the mechanical advantage provided by a plunger to optimize the use of injection gas. The installation of a plunger into a well bore that has a continually declining or erratic liquid level requires constant vigilance on the part of the system operator to reduce the volume of gas injected into the production tube to keep the plunger from developing higher and higher velocity as the liquid level decreases. If the SSGL injection is left without adjustment the plunger velocity often increases to a point where the lubricator and the standing valve will be damaged by plunger impact.
In summary, the damage to the progressive cavity and the beam pumps will require a work-over rig for repairs. The damage to the SSGL seldom requires more than a small wire line truck for a few hours to retrieve and repair the damaged components. However, each of these systems, if controlled improperly, can have catastrophic failures that can be physically dangerous to the operator, costly to repair and can inflict environmental damage.
Most production companies have a mix of all the lift system types throughout their fields and while SSGL is the most environmentally friendly and energy efficient, there are fields in which the beam pump and progressive cavity pump systems are used exclusively. For various reasons that include high rates of liquid production, easy access to electricity, lack of a pipeline distribution system to supply high pressure gas for a SSGL system, lack of compressor capacity to support SSGL systems or engineering preference, many wells use beam pumps, progressive cavity pumps and in some circumstances submersible electric pumps. All of these pumps will suffer damage if the liquid level in the well declines to a point where gas enters the pump or the well enters a pumped off condition.
There are various methods that can be used in conjunction with these pump systems to control pump off. In the case of a beam pump or progressive cavity pump, there are flow monitoring devices that can be installed in the liquid ejection line at surface to monitor the liquid flow to make sure it does not contain excessive quantities of gas or does not stop flowing. If an excessive quantity of gas or a no flow condition is detected, the pump will be shut down. In this method, a pump that is driven by an electric motor may be automatically shut down for a period of time and then restarted to pump until the well is pumped off again. A pump that is driven by a gas engine will be shut down and must be restarted by an operator. This method of pump off detection is inherently weak in that pump off is only detected after-the-fact. The influx of gas into the production tube can cause gas locking of the pump, excessive wear due to lack of liquids or excessive corrosion due to free gas in the production tube. Further, there is no provision for constant monitoring of the liquid level in the well bore to make sure the liquid has been reduced to a level below the productive formation. Therefore, acoustic annular liquid levels must be taken at regular intervals to optimize the performance and efficiency of the artificial lift system.
Another method of monitoring pump off in a system using an electricity driven submersible or progressive cavity pump is to monitor the current draw caused by the pump motor. In the case of the progressive cavity pump, if gas is being drawn into the pump, the current draw may increase because of increased friction, due to the lack of lubrication and cooling provided by the production liquids, which in turn causes the electric motor to work harder. In this method, the pump can be shut down for a period of time to allow liquid to enter the well bore before starting the pump again. However, this method of detection is also an after-the-fact detection of pump off and does not compensate for variations of liquid volume entering the well bore. In the case of the submersible electric pump the current draw may decrease as gas enters the pump due to the impellers spinning in a gaseous fluid. In this case, the system would be shut down to keep the pump from overheating due to lack of cooling liquids. Again, detection is after-the-fact and damage may be done to the pump.
In another prior art control system for the electric progressive cavity pump and the submersible electric pump system, the current load is monitored and this value is used to automatically adjust a variable speed drive on the electric motor. This control method resembles the use of a rheostat where power to the system is controlled to allow for speed adjustment of the electric motor and therefore speed adjustment of the pump. In this method, the motor speed is adjusted based on current load to control system pump off. However, adjustments are made in response to after-the-fact detection of pump off and the system is still unable to detect precise liquid levels in the well bore.
With the submersible electric pump, the progressive cavity pump and beam pump system, another inefficiency can develop if the well bore is configured with a deep rat hole. If the pump is placed substantially below the productive formation and into the rat hole and the liquid in the annulus is reduced down to the level of the pump, it will require significantly more energy to lift the liquid from the well bore than would be required if the liquid level in the annulus was up to the bottom of the productive formation or at the top of the rat hole. For example, if a well is 1000 feet deep to the base of the productive formation and has a 200 feet deep rat hole for a total well depth of 1200 feet, and the liquid being pumped has the density of fresh water with a pressure gradient of 0.433 psi per vertical foot, the head pressure of a liquid column inside the production tube at a depth of 1000 feet will be 433 psi and at a depth of 1200 feet the liquid head pressure will be 519.6 psi. In this scenario if a pump is set to a depth of 1200 feet (200xe2x80x2 into the rat hole below the productive formation) and the liquid level in the annulus is lowered to the level of the pump, the pump must overcome 1200 feet of hydrostatic head pressure or 519.6 psi to lift the liquid to the surface of the ground. Alternately, if the pump is set to a depth of 1200 feet but the liquid level in the annulus is maintained up to the bottom of the productive formation (200 feet above the pump in the annulus) the pump will only need to overcome 433 psi of hydrostatic head pressure to lift the liquid to the surface due to the equalizing force of the liquid in the annulus. In the scenario where the liquid level is reduced unnecessarily low in the annulus it will require approximately 20% more energy to lift a given volume of liquid to the surface than if the liquid level was maintained up to the bottom of the productive formation due to the lack of the balancing effect of the liquid in the annulus.
Therefore, there is a need to provide a method and system to conserve energy and increase longevity of the well bore equipment by precise control of the liquid level within the well bore to avoid pump off in artificial lift systems. A systemic method of control of the liquid level will improve the efficiency of the pump while further reducing the manpower requirements to operate the system by reducing the need for operator intervention with the artificial lift system to control liquid level to optimize well production and to prevent the system from damaging itself. There is further a need to have cost effective oil or gas well artificial lift systems that are relatively environmentally and operationally safe, low maintenance, operationally predictable, easy to use, have an acceptable level of efficiency and have the ability to automatically compensate to meet the variable conditions of a dynamic well bore.
The invention relates to a method and system of producing gas and liquid from a gas and liquid-containing underground stratum comprising a well bore extending between the surface of the ground to the stratum, the well bore having a casing and a production tube defining an annulus through which gas from the stratum passes and is collected at the surface of the ground through a production line. The production tube extends from the surface of the ground and is in fluid communication with the gas and liquid-containing stratum through which the liquid is collected from the well and removed to the surface by artificially raising the liquid in the production tube to the surface to thereby release gas from the formation to the well bore and production line. A side string tube extends from the surface of the ground through the annulus and is in fluid communication with the gas and liquid-containing stratum. An artificial lift system is provided for artificially raising the liquid in the production tube to the surface to thereby release gas from the formation to the well bore and production line.
According to the invention, a system for determining a liquid level of a column of liquid liquid exhibiting a predetermined pressure gradient contained in a well for controlling an artificial lift system for said well based on said liquid level of said column of liquid comprises introduction means for introducing a gas adjacent to a bottom of said column of liquid wherein the gas is introduced at a predetermined rate of flow so as to exhibit a predetermined negligible amount of pressure resistance due to frictional gas flow and sufficient to overcome a pressure exerted by said column of liquid adjacent to a bottom of said well. A sensing means is fluidly coupled to the introduction means for sensing a liquid column pressure at which said gas overcomes said pressure exerted by said column of liquid adjacent the bottom of said well. A processing means is responsive to said sensing means for determining the liquid level of said column of liquid from said pressure exerted by said column of liquid and said predetermined pressure gradient.
Further according to the invention, a system for determining a liquid level of a column of liquid having a predetermined pressure gradient in a well for controlling an artificial lift system for said well, based on said liquid level of said column of liquid, comprises an introduction means for introducing a gas adjacent to a bottom of said column of liquid, said gas being introduced at a predetermined rate of flow so as to exhibit a predetermined negligible amount of pressure resistance due to frictional gas flow and sufficient to overcome a hydrostatic pressure of the column of liquid adjacent a bottom of said well and sufficient to overcome a first pressure of gas in a space in the well above the column of liquid. A first sensing means is fluidly coupled to the introduction means for sensing a second pressure at which said gas overcomes the hydrostatic pressure of said column of liquid adjacent the bottom of said well and the first pressure. A second sensing means is coupled to the space in said well for sensing the first pressure in said space and a processing means is responsive to the first sensing means and said second sensing means for determining the liquid level based on the predetermined pressure gradient of the column of liquid and the difference between said hydrostatic pressure of said column of liquid and said first pressure.
In one embodiment, the liquid level is an annular liquid level inside said well. Preferably, the processing means determines said liquid level from dividing said liquid column pressure by said predetermined pressure gradient.
In a preferred embodiment, the processing means also controls a gas lift system fluidly coupled to said column of liquid in said well by controlling the injection rate of gas being introduced into said well based on comparing the determined liquid level against a predefined liquid level. Preferably, the processing means also controls said gas lift system intermittently through a timed relay connection to a motorized valve in the gas lift supply to said well.
In another embodiment, the processing means also controls the cycling of pumping units fluidly coupled to said column of liquid in said well, which remove the liquid in said well based on comparing the determined liquid level against a predefined liquid level.
In yet another embodiment, the processing means also controls a plunger lift system fluidly coupled to said column of fluid in said well for removing the liquid based on comparing the determined liquid level against a predefined liquid level.
In a preferred embodiment, the introduction means is a side string tube running from the surface to said bottom of the column of liquid so as to permit said gas to bubble up through said column of liquid when the pressure of said gas overcomes the pressure at said bottom of said column of liquid. Preferably, the sensing means is a pressure transducer converting the pressure sensed in said side string tube to electrical information transmitted to said processing means over a wired connection between said pressure transducer and said processing means. Further, the processing means is a programmable controller configured with software instructions for determining said liquid level and the processing means has knowledge of the predetermined pressure gradient of said column of liquid.
Still further according to the invention, a method for determining a liquid level of a column of liquid having a predetermined pressure gradient in a well for controlling an artificial lift system for said well, based on said liquid level of said column of liquid, comprises the steps of introducing a gas adjacent to a bottom of said column of liquid at a predetermined rate of flow so as to exhibit a predetermined negligible amount of pressure resistance due to frictional gas flow and sufficient to overcome a hydrostatic pressure of said column of liquid adjacent a bottom of said well as well as a first pressure of any gas in a space in the well above the column of liquid; sensing through a fluid coupling a second pressure at which said gas overcomes said hydrostatic pressure and said first pressure; sensing through another fluid coupling the first pressure; and determining said liquid level based on said predetermined pressure gradient and the difference between said second pressure and said first pressure.
In one embodiment, the liquid level is an annular liquid level in said well. Preferably, the liquid level is determined by dividing the difference between said second pressure and said first pressure by the predetermined pressure gradient.
In another embodiment, the invention further comprises the step of controlling a gas lift system in said well by controlling the injection rate of gas being introduced into said well based on comparing the determined liquid level against a predefined liquid level. Preferably, the gas lift system is controlled intermittently through a timed relay connection to a motorized valve in a gas supply to the gas lift system in said well.
In yet another embodiment, the cycling of pumping units for removing the column of liquid in said well is controlled based on comparing the determined liquid level against a predefined liquid level.
In yet another embodiment, a plunger lift system in said well for removing the column of liquid is controlled based on comparing the determined liquid level against a predefined liquid level.
In yet another embodiment, the step of introducing a gas to the bottom of said column of liquid is through a side string line extending from the surface to said bottom of the column of liquid so that the gas bubbles up through the column of liquid when the pressure of the gas overcomes the pressure at said bottom of the column of liquid.
In the embodiment of the invention wherein the artificial lift system comprises a gas injection system with an injection valve for periodically injecting a blast of gas into a lower portion of the production tube through the side string tube, the controller is operably connected to the injection valve and is adapted to control the initiation of the blast of gas into the production tube to artificially lift the liquid in the production tube to the surface of the ground. The controller actuates the injection valve to initiate the injection of gas into the side string tube when the measured level of liquid in the production tube reaches a predetermined value representative of the desired level of liquid in the production tube and well bore. Preferably, the controller is adapted to compute the level of liquid in the production tube in response to the first pressure signal after liquid has been substantially cleared from the side string tube by the injection of a minuscule volume of gas.
In a preferred embodiment of the invention wherein the artificial lift system comprises a gas injection system, a second pressure sensor is fluidly attached to the production tube to sense the pressure therein and to generate a second pressure signal representative of the pressure in the production tube. A controller is operably coupled to the second pressure sensor and is adapted to compute the level of liquid in the production tube in response at least in part to the first and second pressure signals. In a preferred embodiment of the invention, the controller is adapted to compute the level of liquid in the production tube in response to the difference between the first and second pressure signals.
In another embodiment of the invention, the artificial lift system comprises a beam pump. In still another embodiment of the invention, the artificial gas lift system comprises a progressive cavity pump. In still another embodiment of the invention, the artificial lift system is an electrically driven submersible pump.
In a preferred embodiment of the invention wherein the artificial lift system incorporates a pump, a second pressure sensor is fluidly attached to the annulus to sense the pressure therein and to generate a second pressure signal representative of the pressure in the annulus. A controller is operably coupled to the second pressure sensor and is adapted to compute the level of liquid in the well bore in response at least in part to the first and second pressure signals.
According to one aspect of the invention, the controller is adapted to compute the level of liquid in the well bore in response to the difference between the first and second pressure signals. Preferably the controller is adapted to generate an output signal for controlling the initiation of the artificial lift system when the liquid level in the well bore as detected by pressure reaches a predetermined value.
The invention can be applied to a single producing well with the controller physically at the wellhead. Alternatively, a controller can be used to control a plurality of wells. The controller can be located geographically remote from each of the wells and in communication with the sensors and control valves at the well head through electrical communication lines or through telemetry.
The invention also contemplates several variations of pressure monitoring for control of the artificial lift systems in wells using the beam pump, progressive cavity pump or the electric submersible pump methods of artificial lift, each with the objective of detecting the level of liquid in the well bore prior to making adjustments to the artificial lift system. These methods have varying accuracy according to the operational need dictated by the well bore configuration. In one embodiment of the invention, operational efficiency and control is enhanced by volumetric measurement of production gas to control the operation of the artificial lift system by automated control of the liquid level in the well bore.
Fundamental to an understanding of how the pressure monitoring and control system of the invention can have a positive impact on artificial lift system performance is an understanding of the variations in pressures that can and do exist at various points in the artificial lift system. These pressures, measured at the appropriate time and interpreted correctly, will give a very accurate determination of the liquid level in the production tube and/or well bore.
Pressures in a bore hole are commonly referred to in the terms of pressure gradients. xe2x80x9cGradientxe2x80x9d is defined as psi per vertical foot in the bore hole. Fresh water will have a gradient of 0.433 psi per vertical foot, whereas low pressure gas gradient may be as minimal as 0.002 psi per vertical foot. In effect, a 1000xe2x80x2 column of fresh water will have a bottom hole or head pressure of 433 psi whereas the low pressure gas will have a bottom hole or head pressure of 2 psi.
In a well using the subsurface gas lift (SSGL) method of artificial lift, subsequent to the injection portion of the SSGL cycle, liquid will enter the bottom of the production tube through the standing valve attached to the injection mandrel and displace the gas in the production tube into the ejection line and to the collector at surface until the well bore has achieved static equilibrium. (Static equilibrium is commonly defined as the time when head pressure at the injection mandrel is substantially equalized between the inside of the production tube and the annular section of the well bore. Therefore, a no-flow condition exists between production tube and the annulus.) The column of liquid entering the production tube and displacing the gas into the flow line at surface will at the same time try to enter into the side string tube attached to the injection mandrel above the standing valve. However, the side string tube, unlike the production tube, is closed at surface. Therefore, the liquid can only enter the side string tube until the cumulative head pressure of the gas and liquid in the side string tube at the injection mandrel is equal to the cumulative head pressure of the gas and liquid in the production tube at the injection mandrel. At this point, the difference between the side string injection line pressure at surface and the production tube pressure at surface multiplied by the appropriate liquid gradient pressure factor will give the approximate liquid level in the production tube. The reason the liquid level is only approximate is due to the fact that liquid has entered the side string tube to compress the gas in the side string tube which causes there to be two different gradients in the side string tube, one for gas and one for liquid, the level of which is unknown. At this point, pressure manipulation will accurately determine actual liquid level in the production tube. Manipulation is accomplished by the injection of a minuscule volume of gas into the side string injection line attached to the side string tube. This volume will displace the liquid in the side string tube, causing only gas to be present in the side string tube. This volume is estimated based on the diameter of the side string tube and the estimated height of liquid in the side string tube. Typically, the amount of gas is determined by monitoring the pressure in the side string injection line at surface as the gas is injected into the side string tube and the volume is typically very small as compared to the amount of gas injected during the SSGL injection cycle. The pressure in the side string injection line will increase as the minuscule volume of gas is injected into the side string tube until all of the liquid in the side string tube is forced into the production tube at which time the pressure will stabilize. This step can be carried out manually by an operator or automatically by a controller. As a practical matter, the minuscule volume of gas can be injected continuously between injection cycles to maintain the side string tube free of liquid. As a result, the difference between the pressures in the side string injection line at surface and the production tube at surface multiplied by the appropriate liquid gradient factor is used to compute the level of liquid in the production tube with great accuracy. The computations are done reiteratively until the computed level of liquid in the production tube is equal to a predetermined level which is based on the well bore characteristics. When the predetermined level and the computed levels are equal, the SSGL injection cycle can then be initiated by the controller if desirable. This known level of liquid in the production tube can thus be used to greatly improve the efficiency of the SSGL system by effecting the cycling only when an optimum liquid level has been achieved while eliminating the single greatest control problem for SSGL, the xe2x80x9cdestructive dry cyclexe2x80x9d that often causes mechanical damage and can cause environmental damage.
The invention uses variations of a method of liquid level detection to provide improved control methods and apparatus for various types of gas or oil well artificial lift systems which enhance efficiency, improve production, are cost effective, environmentally friendly, contribute to operational predictability and safety, are diverse enough to accommodate various well bore configurations, and are able to automatically accommodate a dynamic well bore and support the prudent and timely use of energy resources.